To obtain hydrocarbons such as oil and gas, boreholes are drilled by rotating a drill bit attached at a drill string end. A large proportion of the current drilling activity involves directional drilling, i.e., drilling deviated and horizontal boreholes, to increase the hydrocarbon production and/or to withdraw additional hydrocarbons from the earth's formations. Modem directional drilling systems generally employ a drill string having a bottomhole assembly (BHA) and a drill bit at end thereof that is rotated by a drill motor (mud motor) and/or the drill string. A number of downhole devices placed in close proximity to the drill bit measure certain downhole operating parameters associated with the drill string. Such devices typically include sensors for measuring downhole temperature and pressure, azimuth and inclination measuring devices and a resistivity measuring device to determine the presence of hydrocarbons and water. Additional downhole instruments, known as logging-while-drilling (“LWD”) tools, are frequently attached to the drill string to determine the formation geology and formation fluid conditions during the drilling operations.
Pressurized drilling fluid (commonly known as the “mud” or “drilling mud”) is pumped into the drill pipe to rotate the drill motor and to provide lubrication to various members of the drill string including the drill bit. The drill pipe is rotated by a prime mover, such as a motor, to facilitate directional drilling and to drill vertical boreholes. The drill bit is typically coupled to a bearing assembly having a drive shaft which in turn rotates the drill bit attached thereto. Radial and axial bearings in the bearing assembly provide support to the radial and axial forces of the drill bit.
Boreholes are usually drilled along predetermined paths and the drilling of a typical borehole proceeds through various formations. The drilling operator typically controls the surface-controlled drilling parameters, such as the weight on bit, drilling fluid flow through the drill pipe, the drill string rotational speed (r.p.m of the surface motor coupled to the drill pipe) and the density and viscosity of the drilling fluid to optimize the drilling operations. The downhole operating conditions continually change and the operator must react to such changes and adjust the surface-controlled parameters to optimize the drilling operations. For drilling a borehole in a virgin region, the operator typically has seismic survey plots which provide a macro picture of the subsurface formations and a pre-planned borehole path. For drilling multiple boreholes in the same formation, the operator also has information about the previously drilled boreholes in the same formation. Additionally, various downhole sensors and associated electronic circuitry deployed in the BHA continually provide information to the operator about certain downhole operating conditions, condition of various elements of the drill string and information about the formation through which the borehole is being drilled.
Typically, the information provided to the operator during drilling includes: (a) borehole pressure and temperature; (b) drilling parameters, such as WOB, rotational speed of the drill bit and/ or the drill string, and the drilling fluid flow rate. In some cases, the drilling operator also is provided selected information about the bottomhole assembly condition (parameters), such as torque, mud motor differential pressure, bit bounce and whirl etc.
The downhole sensor data is typically processed downhole to some extent and telemetered uphole by electromagnetic signal transmission devices or by transmitting pressure pulses through the circulating drilling fluid. Mud-pulse telemetry, however, is more commonly used. Such a system is capable of transmitting only a few (1-4) bits of information per second.
The BHA in a directional wellbore is subjected to bending moments due to side forces acting on the BHA. These side forces can be caused by gravity, drilling dynamic effects, and/or by contact between the borehole wall and the BHA. These bending moments cause deviations from the desired wellbore path that require corrections. In common directional systems, including MWD systems, a directional survey of azimuth and inclination is taken by sensors in the BHA after the drilling of each stand of drill pipe. The measurements allow the determination of a pointing vector having an inclination and direction, also called azimuth, associated with the BRA at each survey location. The difference in the three dimensional angle of the pointing vectors at successive survey stations divided by the path length between stations can be used as a measure of the irregularity of the borehole curvature known as dogleg severity. Common systems measures bending moment and transmit the values to the surface to determine the side forces and stresses in the BHA for a given borehole curvature determined from measured survey data. Commonly, high dogleg severity can cause difficulty in further drilling and/or installing production casing and other downhole equipment. The nature of taking measurements only after each stand exacerbates the problem.
There is a need for a system and method for taking substantially continuous bending measurements that can be used to provide substantially continuous borehole curvature estimates leading to improved borehole quality.